1. Field of the Invention
This invention relates to flexibly extracting and recovering a stream of C.sub.2 + hydrocarbons from a natural gas stream. It more specifically relates to the prevention of hydrate formation during processing of natural gas liquids by the Mehra Process. It further relates to purifying the stream of C.sub.2 + hydrocarbons before use thereof as a natural gas liquid product stream.
2. Review of the Prior Art
Natural gas is a mixture of hydrocarbons, including methane, ethane, propane, and various amounts of higher molecular weight hydrocarbons together with acid gases, such as CO.sub.2 and/or H.sub.2 S. A "dry" gas is one containing predominantly methane with some ethane, propane, and butane with a very low hydrocarbon dew point. The heavier the hydrocarbons, such as pentane and higher homologs that are present in the gas, the higher the hydrocarbon dew point. For pipeline transmission, enough of the heavier hydrocarbons must be removed to lower the dew point without losing BTUs to meet specifications. In the past, gas with large quantities of high molecular weight hydrocarbons have been passed through gasoline extraction plants and/or dew point control stations to lower the dew point. Also, frequently the gas has required conditioning to remove sulfur compounds and carbon dioxide.
A natural gas stream coming from the wellhead is also usually saturated with water at its ambient temperature which may have a range of 75.degree.-120.degree. F. so that its water content may vary from 20 pounds to more than 50 pounds per million standard cubic feet. However, difficulties are frequently met while pumping such natural gas, such as formation of ice and hydrates or the accumulation of water which can block the flow as well as cause corrosion, unless the water content is reduced to a value of less than 12 pounds, preferably less than 7 pounds, of water per million standard cubic feet of natural gas. In terms of dew point, a natural gas having a dew point of 30.degree. F., preferably 20.degree. F. or lower, is generally considered safe for transportation in a pipeline. Dehydration can be carried out under a wide range of pressures from 15 to 5,000 PSIG, but it is usually carried out at pipeline pressures of 500-1,500 psig.
Dehydration and sweetening of natural gas has been done with physical solvents, as taught in U.S. Pat. Nos. 3,362,133, 3,770,622, and 3,837,143, but always with an economic penalty from losses of hydrocarbons that were absorbed with the acid gases. Such losses can be appreciated in view of the relative solubilities of the acid gases and the hydrocarbons in physical solvents.
The Mehra process took advantage of the liabilities of the prior art processes by utilizing the relative solubilities of the hydrocarbons in physical solvents for the specific purpose of isolating and recovering the hydrocarbons. Specifically, the Mehra process handles any natural gas, from very sour to entirely sweet, in the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons with a physical solvent, as disclosed in U.S. Pat. Nos. 4,421,535 and 4,511,381 of Yuv R. Mehra, both of which are herein incorporated by reference. The compositions of its liquid hydrocarbon product and of its residue natural gas product can be readily adjusted in accordance with market conditions so that profitability of the extraction operation can be maximized at all times and on short notice. This process thereby produces a liquid hydrocarbon product having a composition which is selectively versatile rather than fixed, as in prior art processes.
The inlet natural gas streams which may be treated with a physical solvent according to the Mehra process include the following:
A. natural gas saturated with water;
B. natural gas at less than saturation with water;
C. sour natural gas;
D. sour natural gas which is pre-sweetened in gas phase with an aqueous amine solution;
E. sweet natural gas; and
F. dry natural gas.
Such versatility is achieved by flexibility in certain operating conditions and by use of certain additional steps that are not used in the prior art. These conditions and steps are listed as follows, in order of importance:
(1) varying the flow rate of a physical solvent with respect to flow rate of the natural gas stream in an extraction column to produce the rich solvent;
(2) varying the flashing pressure for one or more of the successive flashing stages for the rich solvent;
(3) recycling the flashed C.sub.1 + undesirable gases from the first flashing stage and, selectively, also the second flashing stage to the extraction column;
(4) compressing, cooling, and condensing the flashed gases from the remaining flashing stages to form a crude liquid;
(5) rejecting and returning to the residue gas line selected components of the crude liquid, viz., methane (demethanizing), methane plus ethane (de-ethanizing), methane, ethane, and propane (depropanizing), or methane, ethane, propane, and butanes (debutanizing) in a stripping column for the crude liquid by:
(a) varying the pressure in the column, and PA2 (b) varying the temperature at the bottom of the column; and
(6) recovering the remaining components as the natural gas liquid product.
However, daily changes in market conditions may also cause the price of a single liquid hydrocarbon heavier than ethane to drop below its fuel price so that this hydrocarbon should be selectively rejected, but there was no way in the prior art or in these two patents of doing so without also rejecting all components of lower molecular weight. For example, if the price of ethane was below its fuel value, it could be rejected with methane, as taught in U.S. Pat. Nos. 4,421,535 and 4,511,381, but if the price of propane was below its fuel value while the price of ethane was above its fuel value, both of these hydrocarbons would have to be rejected together because no method existed for separating them. Accordingly, U.S. Pat. No. 4,526,594 of Yuv R. Mehra, which is also incorporated herein by reference, provides a process that is useful when changes in the market prices for individual hydrocarbons in liquid form cause the market price for an individual hydrocarbon liquid to fall below its fuel price. Such prices change on a daily basis so that it becomes advantageous to be able to extract all of the C.sub.2 -C.sub.5 + hydrocarbon liquids while rejecting and returning to the residue gas line one or more of the C.sub.2 -C.sub.4 hydrocarbons that are priced below their fuel values. The extraction plant can thereby be operated at optimum profit levels at all times.
The process of U.S. Pat. No. 4,526,594 accomplishes this selective rejection by subjecting the rejected components of the crude liquid to a second extraction with a portion of the same physical solvent to produce a gas stream of C.sub.1 or C.sub.1 +C.sub.2, which is returned to the residue gas line, and a second rich solvent stream which is singly flashed to produce an overhead gas stream and a liquid mixture which is regenerated to produce the physical solvent stream for the extracting. This gas stream is compressed, cooled, and condensed to form a second crude liquid stream. This liquid stream is split. The bottom portion, of C.sub.3 's or C.sub.3 +C.sub.4 's or C.sub.4 's only, is sent to the residue gas line, and the top portion, of C.sub.2 or C.sub.2 +C.sub.3 or C.sub.3, is combined with the liquid product from the stripping column.
The absorption principle leads to an alpha or relative volatility for methane with respect to ethane of slightly less than 5 for almost all known absorption liquids. However, the relative volatility for methane with respect to ethane in the presence of dimethyl ether of polyethylene glycol (DMPEG) is 6.4, indicating that it is more selective toward ethane than other absorption liquids. N-methyl pyrrolidone (NMP) and dimethyl formamide (DMF) have relative volatilities for methane/ethane of 5.3 and 8.5, respectively. However, the solubility of hydrocarbons in NMP is 0.03 standard cubic feet per gallon (SCF/gal) and in DMF is 0.04 SCF/gal; these are low when compared to 1.0 SCF/gal for DMPEG.
Therefore, it is the combination of improved selectivity towards ethane and the hydrocarbon loading capacity of dimethyl ether of polyethylene glycol that makes it a superior absorption solvent for separating and recovering the components of a natural gas stream that are heavier than methane, in accordance with the disclosures of the Mehra process in U.S. Pat. Nos. 4,421,535, 4,511,381, 4,526,594, and U.S. application Ser. No. 637,210. The minimum qualifications for a physical solvent are a minimum relative volatility of methane over ethane of 5.0 (thereby defining its improved selectivity toward ethane over methane) and minimum solubility of 0.25 standard cubic feet per gallon of the solvent (thereby defining its hydrocarbon loading capacity). However, the ideal physical solvent would have a selectivity toward ethane over methane as high as 10.0, and simultaneously would possess a hydrocarbon loading capacity of about 3.0 SCF/gal. This combination also enables solvent flow rate variation and flashing-pressure variations to be particularly useful for flexibly producing liquid products having selected hydrocarbon compositions.
This physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, sulfolane, and glycol triacetate. The solvent is preferably selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof, and the solvent most preferably is dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.
The glycol can be branched, such as polypropylene glycol. The basic difference between the behaviors of ethyl and propyl groups is the affinity for water for the ethyl and greater affinity for hydrocarbons for the propyl group. A mixture of dimethyl ethers of polyethylene and polypropylene glycol in various combinations is consequently suitable for recovering ethane plus heavier hydrocarbons from a natural gas. In such a mixture, the content of dialkyl ether of polyethylene glycol should be a minimum of 20% by volume, with dialkyl ether of polypropylene glycol being limited to 80% by volume maximum.
CO.sub.2 and H.sub.2 S have solubilities in DMPEG that are very close to the solubilities of propane and pentane in this solvent. Therefore, it is difficult to separate these acidic materials from the desirable gases when treating sour natural gas. The prior art has tended to perform this separation before removing hydrocarbons, thereby requiring large-capacity equipment and losing significant quantities of desirable hydrocarbons with CO.sub.2 and H.sub.2 S vent streams. Widespread usage of DMPEG has obviously been avoided.
In one of the embodiments of the Mehra process, CO.sub.2 and H.sub.2 S are allowed to remain with the desirable gases until final stages in the process where they are removed as liquids, thereby requiring smaller and less expensive equipment because the equipment's size is determined by mode of treating, i.e., in gas phase or liquid phase.
This treatment procedure requires the usage of substantially larger quantities of DMPEG than has been recommended by the prior art, since the quantity of C.sub.2 + hydrocarbons is generally larger than the quantities of CO.sub.2 and H.sub.2 S in a relatively sweet natural gas stream. There is, consequently, enough absorption capacity in the DMPEG stream when equilibrium is reached that the acidic materials in the recycle stream and in the sour natural gas can be completely removed, thereby producing a sweet methane-rich stream from the top of the extractor that meets pipeline specifications.
An advantage of this treatment method over those of the prior art is that a single plant can accept a very wide variety of natural gas streams, from very acidic to completely sweet, simply by utilizing the acid removal unit (e.g., an amines process) to a selective extent or even by by-passing it entirely. Although liquid-phase sweetening requires a lower capital investment and has lower operating costs than gas-phase sweetening, there are compensating factors in favor of gas-phase sweetening. These include the use and pumping of smaller quantities of solvent and the availability of maximum flexibility as to hydrocarbon composition in the liquid product.
It is preferred that amine processes (MEA, DEA, or DGA) be utilized for removing acid gas components (CO.sub.2 and H.sub.2 S) in gas phase before proceeding with this invention process. The sweet natural gas thus produced will be saturated with water vapor at the pipeline pressures and operating temperatures because any amine process is aqueous based and introduces water vapor into the natural gas stream.
Alternatively, acid gas components can be removed in the liquid phase downstream of processing according to this invention process by amine processes using MEA or DEA. For maximum flexibility of recovering ethane versus rejecting ethane while recovering all of propane plus heavier hydrocarbons in contrast to recovering propane versus rejecting ethane and propane while recovering all of butane plus heavier hydrocarbons, it is preferred that the sour natural gas stream be treated with aqueous amine processes in gas-phase operation in order to extract CO.sub.2 and H.sub.2 S components without losing any hydrocarbons.
As disclosed in a paper entitled "High CO.sub.2 -High H.sub.2 S Removal With SELEXOL Solvent", that was presented by John W. Sweny at the 50th Annual Gas Processors Association Convention, Mar. 17-19, 1980, the relative solubility of CO.sub.2 over methane in a mixture of dimethyl ethers of polyethylene glycol (DMPEG) is 15.0 and the relative solubilities of various hydrocarbons present in a natural gas stream are disclosed as varying from 6.4 to about 165, whereas the similar relative solubility of water is 11,000.
These data appear to indicate that when a physical solvent, such as DMPEG, is flashed to lower pressures, the hydrocarbons separated from the natural gas stream should be essentially dry with respect to water because they have much less relative solubility in the solvent when compared to the solubility of water. However, in the Mehra process, these hydrocarbons are compressed, cooled, and condensed before they are fractionated to make a desired natural gas liquid product (NGL). In consequence, when the condensing temperature of the compressed gases is lower than their hydrate temperature, any water that may be present in these condensed hydrocarbons will tend to freeze in the equipment and thereby prevent the Mehra process from continuing to operate.
It is therefore pertinent that a recent discovery has been made that water, as determined by equilibrium conditions, will nevertheless be present with the flashed hydrocarbon gases, especially when the solvent separation from hydrocarbons is carried out at near-atmospheric pressures, regardless of the multifold differences between the solubility of water and the solubility of heavier components of the natural gas stream in the physical solvent. The presence of water also results in poor measurement of natural gas liquids and causes errors, thereby resulting in loss of revenues. There is consequently clearly a need for a method for removing such residual water from the NGL product.
It has also been recently discovered that, especially when vacuum or heated flashes are utilized in the Mehra process, there is a tendency for some of the solvent to remain with the flashed hydrocarbon gases. When these gases are compressed, cooled, and condensed, a major portion of this flashed-over solvent can be recovered in interstages, but a residual amount will continue to stay with the NGL product. This residual amount of solvent will essentially end up in a natural gasoline fraction (C.sub.5 +) of the NGL product and will eventually act as a gumming compound which is undesirable for the gasoline when it is used for motor fuel. Thus there is also a need for a method of removing this residual solvent from the natural gas liquid product.
It is known in the prior art that the problem of freeze can be avoided by drying the gases, before the condensation step and after compression thereof, with: (a) activated alumina, (b) molecular sieves, (c) glycol injection, or (d) methanol injection. Methods of dehydrating gas streams and products therefrom in the prior art with methanol appear to concentrate on cold temperature treatments when liquid desiccants or solvents are used. Other methods include sequential treatments with two or more solvents, the desiccant solvent being used on the gas stream generally after sulfur-absorbing treatment.
U.S. Pat. 2,238,201 describes a process of purifying hydrocarbon liquids, especially mixtures of hydrocarbons such as gasoline or lower boiling hydrocarbons, with a primary, secondary, or tertiary aliphatic amine, or mixtures thereof. The amine absorbent is a water-soluble, basic-reacting amine having a boiling point above that of water and a high distribution ratio for water over hydrocarbons. Satisfactory amines are members of the ethanolamines, isopropanolamines, polyethylenes and polypropylenes, the aminopropanediols, and the diaminopropanols. Preferred compounds are monoethanolamine, diaminoisopropanol, and particularly diethylene triamine and triethylene tetramine, or commercial mixtures thereof. The liquid hydrocarbon is admixed with an aqueous amine solution and then passed into a large gravity separator from which the hydrocarbon liquid containing some dissolved amine is drawn into a second mixing system wherein it is thoroughly mixed with pure water and passed through a second gravity separator. A purified hydrocarbon liquid is withdrawn from the top layer of the second gravity separator. The lower layers of both gravity separators are drawn off, combined, and heated to expel volatile impurities and regenerate the amine solution.
In U.S. Pat. No. 2,794,334, a method is taught which comprises countercurrently contacting a hydrocarbon gas with a refrigerated aqueous solution of 60-90% methyl alcohol in a specific manner and in sufficient volume to liquefy the liquid fraction as the refrigerant flows downwardly in a column countercurrently to the unliquefied hydrocarbon gas flowing upwardly.
U.S. Pat. No. 2,863,527 relates to the purification of combustible gases containing at least one of carbon monoxide, hydrogen, and methane, such as those gases obtained from distilling or gasifying solid carbonaceous fuels. The purification includes washing the gas at temperatures below zero and as low as -30.degree. C., while at a pressure of at least two atmospheres, with a polar organic washing agent (methanol being preferred) having a freezing point below the washing temperature and being substantially chemically inert to the impurities to be removed. Removal of non-polar constituents from the gas is partially accomplished by the methanol but is aided by the addition of a non-polar washing agent such as low-boiling aliphatic or cyclic straight-chained or branched-chained hydrocarbons. It is preferred to use eutectic mixtures, with a low solidification point, which contain about 1-50% water as the polar organic washing agent in order that they can absorb water from the gas.
U.S. Pat. No. 3,690,816 relates to removing impurities, such as hydrogen sulfide, carbon dioxide, and/or water, from a hydrocarbon gas or liquid. The gas to be purified is passed into an absorber in which it is countercurrently contacted by cool, lean, aqueous monoethanolamine. Purified gas leaves the top of the absorber. Rich absorbent solution leaves the bottom of the absorber, passes through a heat exchanger in which it is heated, and then enters a stripper column, within which stripping vapors from heated stripper bottoms rise to an overhead condenser and reflux drum. The impurities are removed from the reflux drum while reflux is returned to the top of the stripper. Hot, lean, aqueous monoethanolamine solution is removed from the bottom of the stripper and passed through the same heat exchanger for cooling and recycling to the top of the absorber.
U.S. Pat. No. 3,886,757 describes a process for treating a stream of natural gas to reduce the moisture content thereof by washing the gas with a liquid desiccant-antifreeze agent, such as aqueous methyl alcohol containing about 15-40 wt. % water. The treated gas stream is then cooled to a low temperature, such as -100.degree. F., so that all methanol and gasoline therein are substantially condensed. These cold liquids are then removed in a separator and scrubbed with water to remove alcohol from the hydrocarbon liquids. The bottoms from the first contactor and from the separator are fractionated to recover the methyl alcohol.
U.S. Pat. 4,233,141 is directed to purifying liquid hydrocarbon gases (LPG) of H.sub.2 S, COS, and, if also present, CO.sub.2 by contacting the LPG with an aqueous solution of diethanolamine at a temperature below the hydrolysis temperature for COS in order to remove the bulk of the H.sub.2 S and CO.sub.2. The LPG is then heated to hydrolysis temperature and mixed with hot diethanolamine solution so that the COS is hydrolyzed to H.sub.2 S and CO.sub.2. The LPG (under sufficient pressure so that it is still liquid and still contains the products of hydrolysis) is then separated from the hot amine solution, cooled, and again brought into contact with diethanolamine solution so that all H.sub.2 S and CO.sub.2 are extracted therefrom.
U.S. Pat. No. 4,302,220 describes a process for simultaneously removing water and hydrogen sulfide from gases by absorbing both materials under superatmospheric pressure with polyethylene glycol dialkyl ethers, stripping the hydrogen sulfide from the loaded solvent, removing the water taken up thereby, and recycling the regenerated solvent for contact with the loaded gases. The solvent contains 0.01-20% by weight, based on a solvent mixture, of an alcohol or ether boiling in the range of from 50.degree. to 140.degree. C. The alcohols used are preferably aliphatic alcohols having 1-5 carbon atoms, methanol being preferred.
U.S. Pat. No. 4,305,733 furnishes a method for the recovery of a methane-rich natural gas from a sour natural gas by initially chilling the natural gas so that water, heavy hydrocarbons, lighter hydrocarbons, and acid gases are condensed for further processing. The gas is then scrubbed with dimethyl isopropyl ether of ethylene glycol at a temperature of -10.degree. C. to remove hydrogen sulfide. The scrubbed gas is then contacted with liquid methanol at -50.degree. C. to remove carbon dioxide. The charged methanol is expanded in a liquid turbine to produce a liquid phase of generally methanol-containing solubilized CO.sub.2 and a gaseous phase consisting of hydrocarbons solubilized in or entrained by the methanol. The expanded methanol is regenerated, and dissolved CO.sub.2 is removed. The gas, after scrubbing with methanol, is essentially pure methane.
U.S. Pat. No. 4,332,596 teaches the selected removal of sulfur compounds, such as H.sub.2 S and carbonyl sulfide (COS), from moist gaseous mixtures by scrubbing these mixtures at a temperature below 0.degree. C. with toluene or xylene as the scrubbing liquid, after the moist gaseous mixture has been contacted with liquid methanol before cooling the mixture to scrubbing temperature. The liquid methanol is partially vaporized so that a methanol concentration of above 2%, preferably 3-8% to about 30% by weight, is maintained in the scrubbing liquid to be recycled from the sump of the thermal regenerating column to the scrubbing column.
U.S. Pat. No. 4,382,855 discloses a process for removing hydroxy-substituted and/or mercapto-substituted hydrocarbons from coal liquids by contacting the liquids with an aqueous composition containing an alkanolamine, thereby providing a two-phase mixture, and then separating the mixture into an aqueous extract phase and a naptha-rich raffinate phase.
U.S. Pat. No. 4,430,196 teaches the neutralization of acidic components in petroleum refining units by adding dimethylaminoethanol and/or dimethylisopropanolamine as a neutralizing agent. When sour crude is to be refined, it is desirable that dimethylisopropanolamine be used in conjunction with dimethylaminoethanol. The neutralizing agents are added in an amount sufficient to elevate the pH of the condensate, as measured at the accumulator, to 4.5-7. Use of a neutralizing agent minimizes corrosive attack on the metals normally used in the low temperature sections of a refinery process system, where water is present below its dew point.
When the intended use of a natural gas is not hampered by the presence of CO.sub.2, the raw natural gas may not be treated with an aqueous amine solution. Similarly, if both CO.sub.2 and H.sub.2 S are present in the raw natural gas, the treatment or "wash" with the aqueous amine solution may be sufficient only to remove the H.sub.2 S. Such "rough and fine washes" are described in U.S. Pat. No. 4,382,855.
The relatively sweet inlet natural gas from a rough amine wash to the Mehra process may contain small amounts of acid gases, particularly CO.sub.2, which the physical solvent will remove from the natural gas. When the rich solvent is flashed, the CO.sub.2 leaves with the C.sub.3 -flashed gases and remains in the liquid natural gas products.
There is accordingly a need for a process for sweetening the NGL product of the Mehra process by removing small quantities or even traces of acid components when sour natural gas has been given merely a rough wash selectively to remove H.sub.2 S to prepare the inlet natural gas for the Mehra process.